Complex reservoirs can be located within clastic and carbonate type environments. This paper reflects the complexity within such and in particular of the clastic family, i.e. sandstones, siltstones. These reservoirs can, on occasion, be associated with limited matrix permeabilities. These permeabilities can be in the range of microdarcies and even as low as nanodarcies with natural fractures (NF) or fissures within the framework which significantly enhance the production levels via secondary porosity mechanisms. In general, the production capability from matrix permeability as identified on their own do not possess sufficient conductivity to keep the reservoir at viable long-term commercial levels of production. Under the conditions where natural fissures/fractures prevail, a situation arises where the induced hydraulic fractures may promote interaction with the natural fracture/fissure resulting in an enhanced fluid leak off, which consequently can arrest the induced fracture and can lead to negative early job screen out.
The propagation of the induced fracture will be dependent on the magnitude of stress on the rock itself and the four (4) listed typical types of natural fracture/fissure interactions. Type 1 fractures provide reservoir storage capacity and permeability. Type 2 fractures provide the permeability and the matrix provides porosity. In Type 3, the matrix permeability already provides sufficient primary permeability with the fractures adding additional flow capacity, and Type 4 natural fractures are filled with minerals and provide neither additional porosity nor permeability. The paper will present alternative options to keep these natural fractures/fissures open after frac.
Common practice in this environment has included the use of 100-mesh sand pumped ahead of the planned hydraulic fracture to minimize the effect of fluid loss. Typically, this methodology has relative success from the viewpoint of job execution and leak-off control; however, this can reduce the conductivity of vugular spaces within the natural fracture/fissure and rock matrix conductivity, and therefore may influence potential production from the reservoir.
It is expected that dilation of the natural fracture and subsequent propping with the placed 100-mesh natural sand is evident for existing open natural fractures. Consequently, there will be losses to the secondary porosity conductivity and the potential ultimate reduction of production of the reservoir. To minimize this effect, a fully self-degrading particulate derived from a natural polylactide polymer (PLA) was used to control the natural fissure interactions and subsequently minimize fluid loss during the induced hydraulic fracturing operation. Since the fully self-degrading particulate-derived PLA technology can control fluid loss into naturally fractured reservoirs while ultimately keeping clean and open fractures without losses in permeability post-induced frac operation, the paper documents the use of three fixed numbers of PLA slugs, pumped ahead of a fracturing stimulation alternating among 1) biodegradable particulates, 2) mixing in defined proportions of 100-mesh proppant particulates, and 3) biodegradable particulates, to allow temporarily plugging the natural fracture spaces without conductivity loss when the fracturing operation is complete. Author informs that the 3 steps of slugs can be reaped with the same fluids anytime that magnitude of Natural Fissures "NF" shows as high density and dips, it is possible increase and or decrease the PLA and natural sand concentrations and volume. The biodegradable particulates completely degrade within a few hours and subsequently leave the natural fracture with fully open, clean pathways for optimum hydrocarbon production potential.